In the very extensive art of solid fuel combustion, reference is frequently made to the desirability of having the fuel as dry as possible. The higher the moisture (water) content the more difficult it is to ignite. Usually, the heat required to vaporize fuel moisture is lost, detracting from that available for useful purpose. This loss, in turn, lowers combustion (flame) temperature. Although, as a necessity or convenience, many fuels, such as forestry and agricultural wastes, are burned in a wet condition, it is with the knowledge that much of their potential energy will be wasted. To dispose of some high moisture wastes, such as garbage and sewage sludge, it is often necessary to fire expensive auxiliary fuels, such as oil or gas, to achieve a temperature high enough to complete the combustion.
Generally speaking, a high combustion temperature is considered desirable in the interest of complete combustion. Based on thermodynamic theory, high temperature heat is considered more valuable than lower temperature heat, even though it is commonly released at a temperature (ca. 2700.degree. F.) some 2000.degree. F. higher than the temperature (usually below 700.degree. F.) at which most of it will be utilized to generate steam.
The usual high combustion temperatures are not without drawbacks: the apparatus must be constructed of expensive materials capable of withstanding them. Ash components frequently melt or sinter, forming deposits which foul heat transfer surfaces, obstruct gas passages and damage refractory linings. Fuel sulfur burns to sulfur dioxide while fuel nitrogen and some atmospheric nitrogen is converted to nitrogen oxides. Sulfur and nitrogen oxides are strongly implicated as major sources of the "acid rain" which is damaging forests and lakes, particularly in northeastern states.
Since man's earliest campfire, solid fuels have been burned almost exclusively at atmospheric pressure. On the small scale this is simple and logical. On the large scale, volumes of air and flue gas become unreasonably great. A 300 Megawatt (MW) boiler, not particularly large by present standards, produces a million cubic feet of flue gas per minute. Consequently, the combustion space needs to be a huge gallery, with all the structure necessary to support it, and the enormous flow of flue gas carries a proportionate burden of fly ash. When emissions controls consisted mainly of a tall stack, such volumes were perhaps tolerable.
But, when environmental awareness made it necessary to filter or precipitate out most of the fly ash, and chemically absorb most of the sulfur dioxide, large scale atmospheric combustion became outdated. Low pressure is not only responsible, in large measure, for the sulfur dioxide but makes it absurdly difficult to remove.
There is an unwritten law in the chemical process industries to the effect that one should never process a gas at low pressure, if it can possibly be avoided. Equipment sizes and energy losses are excessive and entrainment nearly unmanageable. Conventional flue gas desulfurization is an unfortunate illustration of that law. Termed by The Electric Power Research Institute (EPRI) "The Technology Nobody Wanted", its expense, energy waste and operating and maintenance headaches are almost universally deplored. The standoff on acid rain legislation at the time of this application testifies to the widespread resistance to more of this unsatisfactory expedient.
There is somewhat less complaint about the costs of particulate control. Precipitators and baghouses, the devices used to recover fine ash particles, are satisfactory only by comparison with disulfurization. They are large and expensive (because of the low pressure) and consume substantial energy. The tighter particulate emission regulations which are in prospect will make this step even more costly.
A vast labyrinth of ducts, often large enough to drive a truck through, is needed to connect atmospheric boilers with their emissions control systems and stack. Ductwork, alone, for a 300 MW boiler has been estimated to cost $10 million.
Time honored methods of handling solid fuels are pretty much taken for granted, perhaps because thought inevitable. Actually, the numerous mechanical steps from mine to boiler aggregate serious losses, weathering, leaching, labor and energy consumption and production of dust and noise. In fact, they are a major contributor to coal's old fashioned, dirty image.
But the venerable beliefs about solid fuels are being challenged on a broad front. Water is being deliberately mixed with coals to form a liquid Coal-Water Fuel (CWF) (also known as Coal-Water Slurry (CWS) and Coal-Water Mixture (CWM)). Atmospheric Fluidized Bed Combustions (AFBCs) are bringing combustion temperatures down to 1500.degree.-1600.degree. F. (without appreciable efficiency loss) and experimental Fluidized Bed Combustors have been operated at pressures up to 235 pounds per square inch (psi) (PFBCs).
The original stationary form of fluidized bed, or "bubbling-bed", is receiving stiff competition from a new version, Circulating Fluidized Bed Combustors (CFBCs), with which combustion takes place in a relatively high velocity (entrained phase) up-flow reactor which discharges into a hot cyclone separator. Solids (mainly ash and limestone) separated from flue gas are recycled to the base of the reactor, where they mix with incoming fuel and air.
Ground limestone is added to both types of fluidized beds to react with sulfur dioxide. Excess limestone of 50-150 percent is required to remove about 90 percent of the sulfur, sufficient to comply with liberal 1985 emission regulations.
Also, ground limestone is being mixed with air and fuel in specially designed Limestone Injection Multistage Burners (LIMB) and, alternatively, injected into the flue gas stream at various points during its passage through the convection sections of boilers. In such cases, spent and excess limestone is generally recovered dry along with fly ash. A considerable excess is required to achieve sulfur removals of the order of 60 percent.
Although circulating fluidized beds are relatively new in the solid fuel-fired boiler scene, they are quite old as apparatuses for gas-solids contacting. Fluidized bed catalytic cracking units, employing a high solids recirculation between reactor and regenerator, go back to the early 1940's. By the 1950's, circulating fluidized beds with high velocity (entrained phase) reaction zones were being installed at the Sasol synthetic fuels plant in South Africa. About the same time, fluidized "cat crackers" began moving toward high velocity reaction zones, termed "transfer line" or "riser" reactors.
As a by-product of the petroleum conversion taking place in a cat cracker reactor, coke (often called "carbon") is laid down on the fluidized catalyst. This carbon is burned off spent catalyst in the regenerator which is, in fact, a fluidized bed combustor. The regenerator of a heavy oil cat cracker at the Saber refinery in Corpus Christi, Tex., which burns about 750 tons/day of carbon, is the largest fluidized bed combustor in operation at the time of this application.
Commercial CFBCs have operated since 1979. Versions of this combustion apparatus are offered by at least 25 contractors. Except for minor improvements, it is considered public domain.
Rail transport of solid fuels from source to point of use adds substantially to their cost. For many years an attractive alternative has appeared to be pipeline transport as a slurry in water. There is one successful U.S. coal slurry pipeline but the technique has not fulfilled its early promise. Besides political and legal obstacles, the costly and inefficient steps of dewatering and drying are conventionally entailed, and the contaminated slurry water presents a disposal problem.
Pipeline experience has been with unstabilized slurries containing about 50 percent water whereas the CWFs, being fired experimentally, are limited to 25-30 percent water and require stabilizers.
Although conventional combustions convert sulfur in the fuel predominently to sulfur dioxide, a small amount of the trioxide is sometimes present in flue gas as discharged. It is customary, therefore, to refer to sulfur oxides for which the shorthand symbol is SO.sub.x. Nevertheless, total SO.sub.x is accounted for as if it were all sulfur dioxide. Similarly, nitrogen oxides, or NO.sub.x, are composed primarily of nitrous oxide (NO) and nitrogen dioxide (NO.sub.2). Since the latter predominates, NO.sub.x is accounted for as if it were all the dioxide. When SO.sub.x and NO .sub.x are specified in parts per million (ppm) this measurement is on a volumetric (molar) basis.
At the time of this application the New Source Performance Standards enforced by the Environmental Protection Agency (EPA) permit SO.sub.x emissions of 1.2 lbs/Million British Thermal Units (MBtu) and, in most cases, require 90 percent removal. The corresponding NO.sub.x emissions allowable are 0.5 lbs/MBtu for subbituminous coal and 0.6 lbs/MBtu for bituminous coal. Expressed as ppm in dry flue gas, the EPA maximums vary somewhat with heating value and excess air, but are roughly 4-500 ppm for both SO.sub.x and NO.sub.x. Environmentalists and EPA favor substantial tightening of the regulations and EPA has advanced a NO.sub.x "target" of 150 ppm.
Total U.S. emissions of SO.sub.x and NO.sub.x are estimated to be 20 Million Tons per year (MT/yr) and 10 MT/yr, respectively. Bills before the Congress in 1984 and 1985 had the objective of forcing a reduction in the sum of these emissions from 30 to 20 MT/yr.